Process for recovery of oil from an oil-bearing formation

ABSTRACT

The present invention is directed to a process for producing oil. The mass action ratio (MAR) of divalent cations to monovalent cations of water from an oil-bearing formation is determined, and an aqueous displacement fluid having a total dissolved solids content of from 200 ppm to 5,000 ppm and a MAR of divalent cations to monovalent cations of from 70% to 130% of the MAR of divalent cations to monovalent cations of the formation water is introduced into the formation. Oil is produced from the formation after introducing the aqueous displacement fluid into the formation.

RELATED CASES

This application claims benefit of U.S. Provisional Application No.61/894,669, filed on Oct. 23, 2013, which is incorporated herein byreference.

FIELD OF THE INVENTION

The present invention is directed to a process for recovery of oil froman oil-bearing formation. In particular, the present invention isdirected to a process for recovering oil from an oil-bearing formationwith a polymer-containing fluid.

BACKGROUND OF THE INVENTION

Only a portion of oil present in an oil-bearing formation is recoverableas a result of the natural pressure of the formation. The oil recoveredfrom this “primary” recovery typically ranges from 5% to 35% of the oilin the formation. Enhanced oil recovery methods have been developed toincrease the amount of oil that may be recovered from an oil-bearingformation above and beyond that recovered in primary recovery.

Water-flooding, in which water is injected through an injection wellinto an oil-bearing formation to mobilize and drive oil through theformation for production from a production well, is a widely used methodof secondary recovery used to increase the amount of oil recovered froma formation beyond primary recovery. The amount of oil produced bywater-flooding may be reduced by water fingering through the oil in theformation due in part to viscosity differences between the injectedwater and oil in the formation rendering water more mobile than oil inthe formation. Oil by-passed by water fingering is left in place in theformation and is typically not recovered by further water-flooding sinceadditional water injected into the formation follows the path of theinitial water through the formation.

Water-soluble polymer has been added to water injected into anoil-bearing formation to increase the viscosity of the water anddecrease the viscosity difference between the injected water and oil inthe formation, improving the water-to-oil mobility ratio and therebyreducing water fingering through the oil. This improves the sweepefficiency of the water in the formation and increases oil recovery. Theaqueous polymer mixture may drive through the formation in a plug-likeflow to mobilize the oil in the formation for production with reducedfingering of the aqueous drive solution through the oil relative towater without polymer.

Ionically charged water-soluble polymers have been utilized with lowsalinity water, where “low salinity” water has a total dissolved solids(“TDS”) content of 15,000 ppm or less, to produce an aqueous polymermixture for use in recovering oil from an oil-bearing formation. Use ofan ionically charged water-soluble polymer with low salinity waterprovides a substantial viscosity increase to the water with a minimumquantity of polymer so that a given polymer concentration will provide ahigher aqueous phase viscosity as the salinity of the aqueous phase isreduced.

The viscosity of an aqueous polymer mixture, however, may be changedupon introduction of the mixture into an oil-bearing formation as aresult of ion exchange, particularly divalent ion exchange, between theaqueous polymer mixture, the rock (minerals and clays) of the formation,and formation water due to differences in ion concentration,particularly divalent cation concentration, between the aqueous polymermixture, the rock of the formation, and the formation water. Ionexchange between the formation water and the aqueous polymer mixtureoccurs upon mixing as the ionic concentration of the mixture offormation water and aqueous polymer mixture equilibrates—and may resultin an increase in total cation and divalent cation concentration in theaqueous environment of the polymer as the aqueous polymer mixture ismixed with formation water having a higher TDS content than the lowsalinity water of the aqueous polymer mixture. Ion exchange between theaqueous polymer mixture and the rock of the formation may result indivalent cations being stripped from the aqueous polymer mixture whenthe water of the aqueous polymer mixture has a lower TDS content thanthe formation water.

The viscosity of the aqueous polymer mixture may be reduced upon mixingwith the formation water if the formation water has a divalent cationconcentration that is greater than the divalent cation concentration ofthe aqueous polymer mixture, thereby altering the mobility ratio of theaqueous polymer mixture to oil in the formation and potentially reducingthe effectiveness of the aqueous polymer mixture to inhibit fingering ofthe mixture through oil in the formation. Furthermore, formation waterhaving a greater divalent cation content relative to the aqueous polymermixture may precipitate polymer from the mixture due to the affinity ofthe polymer for divalent cations, potentially reducing permeability ofthe formation. The viscosity of the aqueous polymer mixture may beincreased if the formation water has a divalent cation content less thanthat of the aqueous polymer mixture and/or if a significant amount ofdivalent cations are stripped from the aqueous polymer mixture by ionexchange with the formation rock, potentially inhibiting flow of themixture through the formation. Furthermore, formation damage and clayswelling may be induced by contact of the aqueous polymer mixture withformation water having a higher divalent cation content relative to theaqueous polymer mixture since the aqueous polymer mixture may stripdivalent cations from the formation and formation water due to theaffinity of the polymer for divalent cations, inducing claydeflocculation. Improved processes are desirable for maintaining theviscosity of aqueous polymer mixtures introduced into an oil-bearingformation to produce oil from the formation.

SUMMARY OF THE INVENTION

The present invention is directed to a process for producing oil from anoil-bearing formation comprising:

-   -   determining the mass action ratio of divalent cations relative        to monovalent cations of water from the oil-bearing formation,        where the mass action ratio of divalent cations relative to        monovalent cations of the water from the oil-bearing formation        is defined by formula (I)

MAR_(fw) =[C ⁺ _((fw))]² /C ²⁺ _((fw))  (I)

-   -   where MAR_(fw) is the mass action ratio of divalent cation to        monovalent cations of the    -   formation water, C⁺ _((fw)) is the concentration of monovalent        ions in the formation water,    -   and C²⁺ _((fw)) is the concentration of divalent cations in the        formation water;    -   providing an aqueous displacement fluid comprising water and an        ionically charged polymer, wherein the water of the aqueous        displacement fluid has a total dissolved solids content of from        200 parts per million by weight (ppmw) to 5,000 ppmw and a mass        action ratio of divalent cations relative to monovalent cations        from 70% to 130% of the MAR_(fw), where the mass action ratio of        the divalent cations to monovalent cations of the water of the        aqueous displacement fluid is defined by formula (II)

MAR_(adf) =[C ⁺ _((adf))]² /C ²⁺ _((adf))  (II)

-   -   where MAR_(adf) is the mass action ratio of divalent cation to        monovalent cations of the    -   aqueous displacement fluid, C⁺ _((adf)) is the concentration of        monovalent ions in the aqueous displacement fluid, and C²⁺        _((adf)) is the concentration of divalent cations in the aqueous        displacement fluid;    -   introducing the aqueous displacement fluid into the oil-bearing        formation to displace oil within the formation;    -   producing oil from the oil-bearing formation subsequent to        introducing the aqueous displacement fluid into the formation.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a diagram of an ionic filter that may be used in the processof the present invention.

FIG. 2 is a diagram of an ionic filter that may be used in the processof the present invention.

FIG. 3 is a diagram of an ionic filter that may be used in the processof the present invention.

FIG. 4 is a diagram of an oil-production and separation system that maybe used in the process of the present invention.

FIG. 5 is a diagram of a well pattern for production of oil than may beused in the process of the present invention.

FIG. 6 is a graph showing the sodium and calcium concentrations ineffluents of a synthetic formation brine, a designed low salinity watersolution, a high salinity polymer solution, and a designed low salinitywater solution injected into an oil-bearing core.

FIG. 7 is a graph showing the magnesium and potassium concentrations ineffluents of a synthetic formation brine, a designed low salinity watersolution, a high salinity polymer solution, and a designed low salinitywater solution injected into an oil-bearing core.

FIG. 8 is a graph showing the viscosity of effluents of a high salinitypolymer solution and a designed low salinity polymer solution injectedinto an oil-bearing core.

DETAILED DESCRIPTION OF THE INVENTION

The present invention is directed to a process in which an aqueousdisplacement fluid comprising water having a total dissolved solids(“TDS”) content of from 200 ppm to 5,000 ppm and an ionically chargedwater-dispersable polymer is introduced into an oil-bearing formationcomprising oil and water, and the viscosity of the aqueous displacementfluid is maintained upon contact with the formation and the water in theformation. The viscosity of the aqueous displacement fluid may beselected or designed to be compatible in terms of mobility with the oilin the formation at formation temperature conditions so that the aqueousdisplacement fluid may drive mobilized oil through the formation insubstantially plug-like flow without substantial fingering of theaqueous displacement fluid through the oil or oil through the aqueousdisplacement fluid. The viscosity of the aqueous displacement fluid maybe a function of the type and concentration of polymer in the aqueousdisplacement fluid and the divalent cation concentration of the aqueousdisplacement fluid—where the divalent cation concentration may affectthe viscosity of the aqueous displacement fluid by its effect on theionically charged polymer. Prior to introducing the aqueous displacementfluid into the formation, the ionic polymer species and the divalentcationic content of the aqueous displacement fluid may be selected ordesigned to provide the aqueous displacement fluid with a viscosityeffective to provide the aqueous displacement fluid with a mobilityeffective to enable the aqueous displacement fluid to drive mobilizedoil in the formation in a substantially plug-like flow at formationtemperature conditions.

In the process of the present invention, the viscosity and relativemobility of the aqueous displacement fluid may be maintained uponintroduction of the aqueous displacement fluid into the oil-bearingformation and contact with formation water and formation clays, rocks,and/or minerals by selecting or designing the ionic content of theaqueous displacement fluid such that the mass action ratio (“MAR”) ofdivalent cations to monovalent cations of the aqueous displacement fluidis comparable to, or insubstantially different from, the MAR of divalentcations to monovalent cations of the formation water and the formationrock. As used herein, the MAR of divalent cations to monovalent cationsof the aqueous displacement fluid or the water in the formation or theformation rock is defined as the ratio of the sum of the concentrationsof monovalent cations squared to the sum of the concentrations ofdivalent cations in the aqueous displacement fluid or the formationwater or the formation rock, or MAR=(C⁺)²/(C²⁺), where C⁺ is the sum ofthe concentration of all monovalent cation species in milliequivalentsper liter, and C²⁺ is the sum of the concentration of all divalentcation species in milliequivalents per liter—the definition utilizes asum of concentrations rather than a conventional product ofconcentrations to simplify the calculation on the assumption thatmonovalent cations will react similarly (e.g as a species, compared todivalent cations) and divalent cations will react similarly (e.g. as aspecies, compared to monovalent cations). When used herein “MAR” refersto the MAR of divalent cations to monovalent cations. When the aqueousdisplacement fluid has a MAR that is comparable to the formation waterMAR and the formation rock MAR (which are similar since the cationexchange between the formation water and formation rock is in a state ofequilibrium), little change in the divalent cation to monovalent cationratio occurs within the aqueous displacement fluid, the formation water,and the formation rock when the aqueous displacement fluid is contactedwith the formation water and the formation rock. As a result, theviscosity of the aqueous displacement fluid is not increased or reducedas a result of a change in the divalent cation to monovalent cationratio as the aqueous displacement fluid is contacted with the formationand the formation water, and the viscosity of the aqueous displacementfluid may be maintained at or near an optimal viscosity for inhibitingfingering of the aqueous displacement fluid through oil in the formationor vice versa as the aqueous displacement fluid is utilized to mobilizeand force oil through the formation for production from the formation.

The process of the present invention involves determining the MAR ofwater from an oil-bearing formation, providing an aqueous displacementfluid comprising water and an ionically charged polymer, where the waterof the aqueous displacement fluid has a total dissolved solids (“TDS”)content of from 200 parts per million by weight (ppmw) to 5,000 ppmw anda MAR from 70% to 130% of the MAR of the water from the formation;introducing the aqueous displacement fluid into the oil-bearingformation to displace oil within the formation; and producing oil fromthe formation subsequent to introducing the aqueous displacement fluidinto the formation. The MAR of the formation water is defined herein byformula (I):

MAR_(fw)=(C ⁺ _((fw)))² /C ²⁺ _((fw)))  (I)

where MAR_(fw) is the mass action ratio of divalent cation to monovalentcations of the formation water, C_((fw)) is the sum of theconcentrations of monovalent cations in milliequivalents per liter inthe formation water and C²⁺ _((fw)) is the sum of the concentrations ofdivalent cations in milliequivalents per liter in the formation water.The MAR of the aqueous displacement fluid is defined herein by formula(II):

MAR_(adf)=(C ⁺ _((adf)))² /C ²⁺ _((adf)))  (II)

where MAR_(adf) is the mass action ratio of divalent cations tomonovalent cations of the water of the aqueous displacement fluid, C⁺_((adf)) is the sum of the concentrations of monovalent cations inmilliequivalents per liter in the aqueous displacement fluid, and C²⁺_((adf)) is the sum of the concentrations of divalent cations inmilliequivalent per liter in the aqueous displacement fluid. The processof the present invention may further involve determining the viscosityof oil in the formation and providing an aqueous displacement fluidhaving a viscosity of from 10% to 500% of the viscosity of the oil inthe formation, where the viscosity of the aqueous displacement fluid andthe oil may be determined at a temperature within a range oftemperatures in the formation.

The MAR of divalent cations to monovalent cations of water from theoil-bearing formation may be determined by obtaining a sample of waterfrom the oil bearing formation, measuring the concentrations of eachdivalent cation species and each monovalent cation species in theformation water, and calculating the formation water MAR_((fw))according to formula (I) above. Samples of water from the oil-bearingformation may be obtained in accordance with conventional methods knownto those skilled in the art of producing oil. For example, formationwater may be obtained by drawing fluids from a formation through a welland separating the formation water from other produced fluids such asoil. The divalent cation concentration of divalent cation species andthe monovalent ion concentration of monovalent cation species in theformation water sample may be determined in accordance with conventionalmethods known to those in the art of analytical chemistry.

After determining the MAR of the formation water, an aqueousdisplacement fluid comprised of water and a water dispersable ionicpolymer is provided having a TDS content of 200 ppm to 5,000 ppm and aMAR from 70% to 130% of the MAR of the formation water. The water of theaqueous displacement fluid may be provided from natural source waterhaving a TDS content of from 200 ppm to 5,000 ppm and a MAR of from 70%to 130% of the MAR of the formation water. Alternatively, the water ofthe aqueous displacement fluid may be provided from a source waterhaving a TDS content outside of the range of from 200 ppm to 5,000 ppmand/or having a MAR of less than 70% or greater than 130% of the MAR ofthe formation water, wherein the source water is treated to adjust theTDS content to within a range of from 200 ppm to 5,000 ppm, or istreated to adjust the MAR to a MAR of from 70% to 130% of the MAR of theformation water, or is treated to adjust the TDS content to within arange of 200 ppm to 5,000 ppm and to adjust the MAR to a MAR of from 70%to 130% of the MAR of the formation water.

The water of the aqueous displacement fluid may be provided from asource water having a TDS content of from 200 ppm to 5,000 ppm, or maybe provided from a source water having a TDS content of less than 200ppm or greater than 5,000 ppm that is treated to condition the water tohave a TDS content of from 200 ppm to 5,000 ppm. The water of theaqueous displacement fluid may be provided from a low salinity naturalsource water such as an aquifer, a lake, water produced from theoil-bearing formation, or a river comprising water containing from 200ppm to 5,000 ppm total dissolved solids, where the source water may beutilized as the water of the aqueous displacement fluid withoutprocessing to adjust the TDS content of the source water.

In another embodiment, the water of the aqueous displacement fluid maybe provided by processing water from a low salinity natural source watersuch as an aquifer, a lake, or a river or from water produced from anoil-bearing formation wherein the water from the natural source or theoil-bearing formation has a TDS content of from 0 ppm to less than 200ppm. The TDS content of the water having a TDS content of from 0 ppm toless than 200 ppm may be adjusted to 200 ppm to 5,000 ppm by adding oneor more water soluble salts, for example NaCl and/or CaCl₂, to thewater. The one or more water soluble salts may be added to the sourcewater as an aqueous solution of the salt(s), or may be added to thesource water in solid form.

In another embodiment, the water of the aqueous displacement fluid, orat least a portion thereof, may be provided by processing a salinesource water. The saline source water to be processed may have a TDScontent of greater than 10,000 ppm, or at least 20,000 ppm, or at least25,000 ppm, or at least 30,000 ppm, or at least 35,000 ppm, or at least40,000 ppm, or at least 50,000 ppm, or from 15,000 ppm to 250,000 ppm,or from 20,000 ppm to 200,000 ppm, or from 25,000 ppm to 150,000 ppm, orfrom 30,000 ppm to 100,000 ppm, or from 35,000 ppm to 50,000 ppm. Thesaline source water to be processed to provide the water of the aqueousdisplacement fluid may be selected from the group consisting of aquiferwater, seawater, brackish water, estuarine water, water produced fromthe oil-bearing formation, and mixtures thereof.

Referring now to FIG. 1, a saline source water having a TDS content ofgreater than 10,000 ppm as described above may be processed to produceat least a portion of the water of the aqueous displacement fluid bycontacting the saline source water 111 with an ionic filter 113, wherethe mechanism for processing the saline source water may comprise theionic filter. A portion of the source water 111 may be passed throughthe ionic filter 113 to form treated water 115 having reduced salinityrelative to the source water 111, wherein the treated water may have aTDS content of up to 5,000 ppm, and more preferably of from 200 ppm to5,000 ppm, and most preferably from 500 ppm to 4,000 ppm. At least aportion of the treated water 115 may be utilized as at least a portionof the water of the aqueous displacement fluid.

A portion of the source water 111 may be excluded from passing throughthe ionic filter 113 to form a brine retentate 117 having increasedsalinity relative to the source water. The brine retentate may have aTDS content of at least 20,000 ppm, or from 25,000 ppm to 300,000 ppm.At least a portion of the brine retentate may be utilized as describedin further detail below.

If the treated water has a MAR that is greater than 130% or less than70% of the MAR of the formation water, the treated water may be adjustedso the treated water has a MAR that is from 70% to 130% of the MAR ofthe formation water. Monovalent cation-containing salts, or aqueoussolutions thereof, or divalent cation-containing salts, or aqueoussolutions thereof, may be utilized to adjust the MAR of the treatedwater upwards or downwards to adjust the MAR of the treated water towithin 70% to 130% of the MAR of the formation water. If necessary, atleast a portion of the brine retentate 117 may be added to the treatedwater 115 to adjust the MAR of the treated water to within 70% to 130%of the MAR of the formation water. At least a portion of the MARadjusted treated water may be utilized as the water of the aqueousdisplacement fluid.

The ionic filter 113 may be a membrane based system utilizing ionicseparation membrane units selected from the group consisting of ananofiltration membrane unit, a reverse osmosis membrane unit, andcombinations thereof. A nanofiltration membrane unit may be comprised ofone or more nanofiltration membranes effective for preferentially orselectively removing multivalent ions, including divalent cations, fromthe source water so the treated water may contain less than 80%, or lessthe 90%, or less than 95% multivalent ions and/or divalent cations thanthe source water fed to the nanofiltration membrane(s), and theretentate may contain a corresponding increase of multivalent ionsand/or divalent cations relative to the source water. The one or morenanofiltration membranes of a nanofiltration membrane unit may alsomoderately reduce the monovalent ion content of source water fed to thenanofiltration membrane(s), where the treated water may contain lessthan 20%, or less than 30%, or less than 50%, or less than 70% ofmonovalent ions than the source water fed to the nanofiltrationmembrane(s), and the brine retentate may contain a correspondingincrease of monovalent ions relative to the source water. Nanofiltrationmembranes may be formed of charged polymeric materials (e.g. havingcarboxylic acid, sulfonic acid, amine, or amide functional groups)including polyamides, cellulose acetate, piperazine, or substitutedpiperazine membranes in which a thin ion discriminating layer ofmembrane is supported on a thicker porous material, which is sandwichedbetween the discriminating layer and a backing material. Suitablecommercially available nanofiltration membranes in sheet form or inspirally wound form that may be utilized in a nanofiltration membraneunit in the ionic filter 13 include, but are not limited to, SEASOFT8040DK, 8040DL, and SEASAL DS-5 available from GE Osmonics, Inc., 5951Clearwater Drive, Minnetonka, Minn. 55343, United States; NF200 Series,and NF-55, NF-70, and NF-90 available from Dow FilmTec Corp., 5239 W.73^(rd) St., Minneapolis, Minn., 55345, United States; DS-5 and DS-51available from Desalination Systems, Inc., 760 Shadowridge Dr., Vista,Calif., 92083, United States; ESNA-400 available from Hydranautics, 401Jones Road, Oceanside, Calif. 92508, United States; and TFCS availablefrom Fluid Systems, Inc., 16619 Aldine Westfield Road, Houston, Tex.77032, United States.

A reverse osmosis membrane unit useful in the ionic filter 113 may becomprised of one or more reverse osmosis membranes effective forremoving substantially all ions, including monovalent ions, from thesource water so the treated water may contain less than 85%, or lessthan 90%, or less than 95%, or less than 98% ions than the source waterfed to the reverse osmosis membrane(s), and the brine retentate maycontain a corresponding increase of ions relative to the source water.Reverse osmosis membranes may be spirally wound or hollow fiber modules,and may be asymmetric membranes prepared from a single polymericmaterial, such as asymmetric cellulose acetate membranes, or thin-filmcomposite membranes prepared from a first and a second polymericmaterial, such as cross-linked aromatic polyamides in combination with apolysulfone. Suitable commercially available reverse osmosis membranesthat may be utilized in a reverse osmosis membrane unit in the ionicfilter 113 include, but are not limited to, AG8040F and AG8040-400available from GE Osmonics; SW30 Series and LF available from DowFilmTec Corp.; DESAL-11 available from Desalination Systems, Inc.; ESPAavailable from Hydranautics; ULP available from Fluid Systems, Inc.; andACM available from TriSep Corp., 93 S. La Patera Lane, Goleta, Calif.93117, United States.

Typically, pressure must be applied across the ionic filter 113 toovercome osmotic pressure across the membrane when saline source water111 is filtered to reduce the TDS content of the source water andproduce the treated water 115. The pressure applied across the ionicfilter 113 may be at least 2.0 MPa, or at least 3.0 MPa, or at least 4.0MPa, and may be at most 10.0 MPa, or at most 9.0 MPa, or at most 8.0MPa, and may range from 2.0 MPa to 10.0 MPa, or from 3.0 MPa to 9.0 MPa.The pressure applied across a nanofiltration membrane in the ionicfilter 113 may be in the lower portion of the pressure range relative tothe pressure applied across a reverse osmosis membrane. The pressureapplied across a nanofiltration membrane unit of the ionic filter 113may range from 2.0 MPa to 6.0 MPa, and the pressure applied across areverse osmosis membrane unit of the ionic filter 113 may range from 4.0MPa to 10.0 MPa. If the ionic filter 113 is comprised of membrane unitseither nanofiltration, reverse osmosis, or both combined in a series,the pressure applied across each membrane of the membrane unit may beless than the previous membrane unit by at least 0.5 MPa as lesspressure is required to overcome the osmotic pressure of the permeate ofa preceding membrane unit.

Referring now to FIG. 2, the ionic filter 113 may be comprised of afirst ionic membrane unit 119 and one or more second ionic membraneunits 121 arranged in series, wherein each ionic membrane unit may be ananofiltration membrane unit or a reverse osmosis membrane unit. Thesaline source water 111 having a TDS content of greater than greaterthan 10,000 ppm as described above may be contacted with the first ionicmembrane unit 119 to pass at least a portion of the saline source waterthrough the first ionic membrane unit to form a permeate 123 having areduced TDS content relative to the saline source water, wherein thepermeate may have a TDS content of at least 1,000 ppm, or at least 2,500ppm, or at least 5,000 ppm, or at least 7,000 ppm, or at least 10,000ppm, or at least 15,000 ppm. A portion of the saline source water may beexcluded from passing through the first ionic membrane unit 119 to forma primary brine retentate 125 having increased salinity relative to thesource water. The permeate 123 may be contacted with each of the secondionic membrane units 121 in sequence to pass at least a portion of thepermeate through each of the second ionic membrane units to form treatedwater 115 having reduced salinity relative to the permeate 123 and thesaline source water 111, wherein the treated water may have a TDScontent of from 200 ppm to 5,000 ppm. At least a portion of the treatedwater 115 may be utilized as at least a portion of the water of theaqueous displacement fluid.

A portion of the permeate 123 may be excluded from passing through eachof the one or more second ionic membrane units 121 to form one or moresecondary brine retentates 127. The primary brine retentate 125, one ormore of the secondary brine retentates 127, or a combination of theprimary brine retentate 125 and one or more of the secondary brineretentates 127 may form the brine retentate 117 from the ionic filter113, where the brine retentate 117 has an increased salinity relative tothe source water 111 and may have a TDS content of at least 20,000 ppm,or from 25,000 ppm to 300,000 ppm. At least a portion of the brineretentate 117 formed of the primary brine retentate 125, one or more ofthe secondary brine retentates 127, or a combination thereof may beutilized as described in further detail below.

Referring now to FIG. 3, the ionic filter 113 may be comprised of afirst ionic membrane unit 129 and a second ionic membrane unit 131arranged in parallel, wherein the first ionic membrane unit may becomprised of one or more nanofiltration membranes or one or more reverseosmosis membranes, or a combination thereof, and the second ionicmembrane unit may be comprised of one or more nanofiltration membranes,one or more reverse osmosis membranes, or a combination thereof. A firstportion 133 of the saline source water 111 as described above may becontacted with the first ionic membrane unit 129 and a portion of thefirst portion of the saline source water 133 may be passed through thefirst ionic membrane unit 129 to form a first permeate 135 havingreduced TDS content relative to the saline source water 111. The firstpermeate 135 may have a TDS content of less than 10,000 ppm, or lessthan 7,500 ppm, or less than 6,000 ppm, or less than 5,000 ppm, or from200 ppm to 5,000 ppm. A portion of the first portion of the salinesource water 133 may be excluded from passing through the first ionicmembrane unit 129 to form a first brine retentate 137 having a TDScontent greater than the saline source water 111. The first brineretentate 137 may have a TDS content of at least 20,000 ppm, or at least25,000 ppm, or at least 30,000 ppm, or at least 35,000 ppm, or at least40,000 ppm, or at least 50,000 ppm. A second portion 139 of the salinesource water 111 may be contacted with the second ionic membrane unit131, and a portion of the second portion of the saline source water 139may be passed through the second ionic membrane unit 131 to form asecond permeate 141 having reduced TDS content relative to the salinesource water 111. The second permeate may have a TDS content of lessthan 10,000 ppm, or less than 7,500 ppm, or less than 5,000 ppm, or from200 ppm to 5,000 ppm. A portion of the second portion of the salinesource water 139 may be excluded from passing through the second ionicmembrane unit 131 to form a second brine retentate 143 having a TDScontent of at least 20,000 ppm, or at least 25,000 ppm, or at least30,000 ppm, or at least 25,000 ppm, or at least 40,000 ppm, or at least50,000 ppm. At least a portion of the first and second permeates 135 and141 may be combined to form the treated water 115 having a TDS contentof up to 5,000 ppm, or less than 40,000 ppm, or from 200 ppm to 5,000ppm, where at least a portion of the treated water 115 may be used asthe water of the aqueous displacement fluid. The first brine retentate137, a portion thereof, the second brine retentate 143, a portionthereof, a combination of the first brine retentate 137 and the secondbrine retentate 143, or a combination of portions thereof, may form thebrine retentate 117 which may be utilized as described in further detailbelow.

In an embodiment, the first ionic membrane unit 129 may consist of oneor more nanofiltration membranes and the second ionic membrane unit 131may consist of one or more reverse osmosis membranes. The secondpermeate 141 passed through the second ionic membrane unit 131 may havea TDS content of less than 200 ppm provided the one or more reverseosmosis membranes of the second ionic membrane unit 131 removesubstantially all of the total dissolved solids from the saline sourcewater 111. The first permeate 135 passed through nanofiltrationmembranes may have sufficient monovalent ions therein to have a TDScontent of at least 200 ppm, or at least 1,000 ppm, or at least 2,000ppm, so that the combined first and second permeates form the treatedwater 115 having a TDS content of from 200 ppm to 5,000 ppm.

Referring now to FIGS. 1, 2, and 3, if the treated water 115 has a TDScontent of less than 200 ppm, the TDS content of the treated water maybe adjusted so the treated water has a TDS content to a range of from200 ppm to 5,000 ppm. A portion of the brine retentate 117 may be addedto the treated water 115 to adjust the TDS content from below 200 ppm toa range of from 200 ppm to 5,000 ppm. Alternatively, one or more saltsor aqueous salt solutions, for example NaCl and/or CaCl₂ salts oraqueous salt solutions, may be added to the treated water 115 to adjustthe TDS content of the treated water to a range of from 200 ppm to 5,000ppm. At least a portion of the resulting TDS adjusted treated water maybe utilized as the water of the aqueous displacement fluid.

The water of the aqueous displacement fluid also has a MAR of from 70%to 130% of MAR of the formation water. The water of the aqueousdisplacement fluid may be selected from a water source having a MAR offrom 70% to 130% of the MAR of the formation water or water from a watersource may be treated so the water has a MAR of from 70% to 130% of theMAR of the formation water. The water source may be treated water from asource water that has been treated to adjust the TDS content of thewater to a range from 200 ppm to 5,000 ppm as described above. In oneembodiment of the process of the present invention, water from a lowsalinity natural source water or from a saline source water as describedabove is treated to adjust the TDS content of the water to a range offrom 200 ppm to 5,000 ppm, then the TDS adjusted treated water istreated to adjust the MAR of the TDS adjusted treated water to within70% to 130% of the MAR of the formation water while maintaining the TDScontent of the MAR adjusted water in a range of from 200 ppm to 5,000ppm. In another embodiment, the MAR of water from a low salinity naturalsource water or a saline source water as described above is treated toadjust the MAR of the water to a range of from 70% to 130% of theformation water, then the MAR adjusted water is treated to adjust theTDS content of the MAR adjusted water to a range of from 200 ppm to5,000 ppm as described above while maintaining the MAR of the waterwithin 70% to 130% of the MAR of the formation water. In anotherembodiment, the MAR of water from a low salinity natural source waterhaving a TDS content of from 200 ppm to 5,000 ppm as described above istreated to adjust the MAR of the water to within 70% to 130% of the MARof the formation water while maintaining the TDS content of the water ina range of from 200 ppm to 5,000 ppm. In another embodiment, the TDScontent of water from a low salinity natural source water or a salinesource water having a MAR of from 70% to 130% of the MAR of theformation water is treated to adjust the TDS content to a range of from200 ppm to 5,000 ppm while maintaining the MAR ratio of the water in arange of from 70% to 130% of the formation water. In another embodiment,the water of the aqueous displacement fluid may be selected from asource water having a TDS content of from 200 ppm to 5,000 ppm and a MARin a range of from 70% to 130% of the MAR of the formation water.

The MAR of divalent cations to monovalent cations of water from a sourcewater for use in the aqueous displacement fluid may be determined bymeasuring the concentrations of each divalent cation species and eachmonovalent cation species in the water, and calculating the waterMAR_((adf)) according to formula (II) above. The divalent cationconcentration of divalent cation species and the monovalent ionconcentration of monovalent cation species in the water may bedetermined in accordance with conventional methods known to those in theart of analytical chemistry.

The MAR of the water for use in the aqueous displacement fluid may beadjusted, if necessary, by 1) calculating the amount of monovalentcations and/or divalent cations required to adjust the MAR of the waterto be used in the aqueous displacement fluid to an MAR in a range offrom 70% to 130% of the measured MAR of the formation water; and 2)adding or removing the calculated amount of monovalent cations and/ordivalent cations to the water to adjust the MAR of the water to a rangeof from 70% to 130% of the MAR of the formation water.

Monovalent cations and/or divalent cations may be added to the water tobe used in the aqueous displacement fluid to adjust the MAR of divalentcations to monovalent cations of the water to a range of from 70% to130% of the MAR of the formation water. Monovalent cations and/ordivalent cations may be added to the water by adding a selected amountof one or more selected monovalent cation salts and/or one or moreselected divalent cation salts, or adding an aqueous solution of aselected amount of one or more monovalent cation salts and/or one ormore selected divalent cation salts. In one embodiment of the process ofthe present invention, one or more brine retentates 117, 125, 127, 137,or 143 produced in the treatment of water to reduce the TDS content ofthe water as described above may be added to water to adjust the MAR ofthe water to a range of from 70% to 130% of the formation water.

Monovalent cations and/or divalent cations may be removed from the waterto be used in the aqueous displacement fluid to adjust the MAR ofdivalent cations to monovalent cations of the water to a range of from70% to 130% of the formation water. Divalent cations may be removed fromthe water preferentially relative to monovalent cations by passing thewater through a nanofiltration membrane as described above. Monovalentcations may be removed from the water preferentially relative todivalent cations by passing the water through an ion exchange columnpacked with an ion exchange material selective for adsorbing monovalentcations.

The aqueous displacement fluid also comprises a water-dispersible,preferably water-soluble, ionic polymer that is dispersed in the waterdescribed above. After selection or production of water having a TDScontent of from 200 ppm to 5,000 ppm and a MAR of divalent cations tomonovalent cations that is from 70% to 130% of the MAR of divalentcations to monovalent cations of the formation water, the ionicallycharged polymer is mixed with the water to increase the viscositythereof and to produce the aqueous displacement fluid. The ionicallycharged polymer may be added in an amount effective to increase theviscosity of the treated water to within 10% to 500% of the viscosity ofoil within the oil-bearing formation as measured at a temperature withinthe temperature range in the oil-bearing formation. The ionic allycharged polymer may be added in an amount effective to reduce themobility of the treated water relative to the mobility of oil in placein the formation, preferably so that the mobility ratio of the resultingaqueous displacement fluid relative to oil in the oil-bearing formationis from 0.2 to 5.

The polymer that is mixed with the water to form the aqueousdisplacement fluid may be any ionically charged polymer usable in anenhanced oil recovery application, where the polymer is soluble oruniformly dispersable in the water. The polymer may be a homopolymer ora heteropolymer comprised of two or more monomeric units. The ratio ofmonomeric units of a heteropolymer to be mixed with the treated watermay be selected to provide the aqueous displacement fluid with aselected viscosity in accordance with conventional knowledge in the artof mixing water-soluble or water-dispersable polymers in water. Thepolymer may be a water-soluble polyacrylamide or polyacrylate. Thepolymer may be a partially hydrolyzed polymer. A partially hydrolyzedpolymer for mixing in the treated water may have a degree of hydrolysisof from 0.1 to 0.4, or from 0.2 to 0.3. A preferred polymer for use inthe aqueous displacement fluid is a partially hydrolyzed polyacrylamidehaving a degree of hydrolysis of from 0.15 to 0.4, preferably from 0.2to 0.35. Preferred polymers for use in the aqueous displacement fluidare commercially available partially hydrolyzed polyacrylamides soldunder the trade name of FLOPAAM™ by SNF SAS, particularly FLOPAAM™ 3330and FLOPAAM™ 3630.

The polymer and the water of the aqueous displacement fluid may be mixedby adding the polymer to the water, or adding the water to the polymer,and mixing utilizing any conventional mechanism for mixing water and awater-soluble or water-dispersable polymer. The polymer and the watermay be mixed to form the aqueous displacement fluid by agitating thepolymer and the water in a stirred tank. Excessive shear should beavoided when mixing the polymer and the water to inhibit mechanicalreduction of the size of the polymer molecules.

The polymer may be provided for mixing with the water in a solid powderform or in a concentrated aqueous solution containing from 5 wt. % to 25wt. % of the polymer. If the polymer is provided for mixing in a solidpowder form, the water and polymer should be mixed for a sufficient timeto allow for hydration of the polymer.

The amount of polymer mixed with the water to form the aqueousdisplacement fluid may be selected to provide the aqueous displacementfluid formed with a selected viscosity relative to oil in place in theoil-bearing formation in which the aqueous displacement fluid is to beintroduced. The viscosity of a polymer solution is a function of thepolymer, its molecular weight, the degree of hydrolysis of the polymer,the salinity of the polymer solution, the pH of the solution, thetemperature of the solution, the shear rate, and the concentration ofthe polymer in the solution. The amount of polymer mixed with the watermay be selected to provide the aqueous displacement fluid with aselected viscosity since the polymer, its molecular weight, its degreeof hydrolysis, the salinity and pH of the water of the aqueousdisplacement fluid, and the temperature of the aqueous displacementfluid (relative to the formation temperature) are fixed and the shearrate may be held constant by controlling the pressure at which theaqueous displacement fluid is injected into the formation. The selectedviscosity may be from 10% to 500%, or from 40% to 400% of the viscosityof the oil in place in the oil-bearing formation as determined atformation temperature conditions. The viscosity of the oil in place inthe formation at formation temperature conditions may be determined inaccordance with conventional methods within the art. The selectedviscosity of the aqueous displacement fluid may range from 0.5 mPa s(cP) to 250 mPa s (cP) as measured at a temperature within the range offormation temperature conditions.

The amount of polymer provided in the aqueous displacement fluid mayalso be selected to provide a selected mobility ratio of the aqueousdisplacement fluid relative to oil within the formation. The selectedmobility ratio of the aqueous displacement fluid to oil in the formationmay range from 0.2 to 5, or from 0.5 to 3.

The amount of polymer in the aqueous displacement fluid may be from atleast 350 ppm up to 10,000 ppm by weight of the aqueous displacementfluid. The amount of polymer in the aqueous displacement fluid may rangefrom 500 ppmw to 5,000 ppmw, or from 1,000 ppmw to 2,500 ppmw of theaqueous displacement fluid.

The aqueous displacement fluid is introduced into the oil-bearingformation to enhance recovery of oil from the formation by displacingand mobilizing oil in the formation for production from the formation.The oil-bearing formation may be comprised of a porous matrix material,oil, and connate water. The oil-bearing formation comprises oil that maybe separated and produced from the formation after introduction of theaqueous displacement fluid into the formation.

The porous matrix material of the formation may be comprised of one ormore porous matrix materials selected from the group consisting of aporous mineral matrix, a porous rock matrix, and a combination of aporous mineral matrix and a porous rock matrix. Formation temperaturesmay range from 5° C. to 275° C., or from 50° C. to 250° C.; formationpressures may range from 1 MPa to 100 MPa; pH of the connate water inthe formation may range from 4 to 9, or from 5 to 8; and salinity of theconnate water may range from a TDS content of 2000 ppm to 300,000 ppm.

The rock and/or mineral porous matrix material of the formation may becomprised of sandstone and/or a carbonate selected from dolomite,limestone, and mixtures thereof—where the limestone may bemicrocrystalline or crystalline limestone. Minerals that may form themineral porous matrix material may be clays or transition metalcompounds. Clays that may form at least a portion of the mineral porousmatrix material include smectite clays, smectite/illite clays,montmorillonite clays, illite clays, illite/mica clays, pyrophylliteclays, glauconite clays, and kaolinite clays. Transition metal compoundminerals that may form at least a portion of the mineral porous matrixmaterial include carbonates and oxides, for example, iron oxide,siderite, and plagioclase feldspars.

The porous matrix material may be a consolidated matrix material inwhich at least a majority, and preferably substantially all, of the rockand/or mineral that forms the matrix material is consolidated such thatthe rock and/or mineral forms a mass in which substantially all of therock and/or mineral is immobile when oil, the aqueous displacementfluid, or other fluid is passed therethrough. Preferably at least 95 wt.% or at least 97 wt. %, or at least 99 wt. % of the rock and/or mineralis immobile when oil, the aqueous displacement fluid, or other fluid ispassed therethrough so that any amount of rock or mineral materialdislodged by the passage of the oil, the aqueous displacement fluid, orother fluid is insufficient to render the formation impermeable to theflow of the oil, the aqueous displacement fluid, or other fluid throughthe formation. Alternatively, the porous matrix material may be anunconsolidated matrix material in which at least a majority, orsubstantially all, of the rock and/or mineral that forms the matrixmaterial is unconsolidated. The formation, whether formed of aconsolidated mineral matrix, an unconsolidated mineral matrix, orcombination thereof may have a permeability of from 0.00001 to 15Darcys, or from 0.001 to 1 Darcy.

The oil-bearing formation may be a subterranean formation. Thesubterranean formation may be comprised of one or more porous matrixmaterials described above, where the porous matrix material may belocated beneath an overburden at a depth ranging from 50 meters to 6,000meters, or from 100 meters to 4,000 meters, or from 200 meters to 2,000meters under the earth's surface. The subterranean formation may be asubsea formation.

The oil contained in the oil-bearing formation may have a viscosityunder formation conditions (in particular, at temperatures within thetemperature range of the formation) of at least 0.2 mPa·s (0.2 cP), orat least 1 mPa·s (1 cP), or at least 5 mPa·s (10 cP), or at least 10mPa·s (100 cP). The oil contained in the oil-bearing formation may havea viscosity under formation temperature conditions of from 0.2 to 10,000mPa·s (0.2 to 10,000 cP), or from 1 to 1,000 mPa·s (1 to 1,000 cP) orfrom 1 to 500 mPa·s (1 to 500 cP), or from 1 to 250 mPa·s (1 to 250 cP).Preferably the oil in the oil-bearing formation has a viscosity underformation temperature conditions of from 0.2 to 500 mPa·s so that theaqueous displacement fluid may be provided having a mobility ratiorelative to the oil of at most 2 without inclusion of inordinate amountsof polymer in the aqueous displacement fluid.

Oil in the oil-bearing formation may be located in pores within theporous matrix material of the formation. The oil in the oil-bearingformation may be immobilized in the pores within the porous matrixmaterial of the formation, for example, by capillary forces, byinteraction of the oil with the pore surfaces, by the viscosity of theoil, or by interfacial tension between the oil and water in theformation.

The oil-bearing formation may also be comprised of water, which may belocated in pores within the porous matrix material. The water in theformation may be connate water, water from a secondary or tertiary oilrecovery process water-flood, or a mixture thereof. Connate water in theoil-bearing formation may have a TDS content of at least 500 ppm, or atleast 1,000 ppm, or at least 2,500 ppm, or at least 5,000 ppm, or atleast 10,000 ppm, or at least 25,000 ppm, or from 500 ppm to 250,000ppm, or from 1,000 ppm to 200,000 ppm, or from 2,000 ppm to 100,000 ppm,or from 2,500 ppm to 50,000 ppm, or from 5,000 ppm to 45,000 ppm.Connate water in the oil-bearing formation may have a multivalent ioncontent of at least 50 ppm, or at least 100 ppm, or at least 150 ppm,and may have a multivalent ion content of from 50 ppm to 40,000 ppm, orfrom 100 ppm to 20,000 ppm, or from 150 ppm to 15,000 ppm. Connate waterin the oil-bearing formation may have a divalent ion content of at least20 ppm, or at least 40 ppm, or at least 50 ppm, or at least 100 ppm, orfrom 20 ppm to 35,000 ppm, or from 40 ppm to 20,000 ppm, or from 50 ppmto 15,000 ppm. Preferably the connate water in the formation has at mosta moderate amount of total dissolved solids and a relatively lowconcentration of multivalent cations therein, preferably having a TDScontent of at most 30,000 ppm and a total multivalent cation content ofat most 250 ppm.

The water in the oil-bearing formation may be positioned to immobilizeoil within the pores. Introduction of the aqueous displacement fluidinto the formation may mobilize at least a portion of the oil in theformation for production and recovery from the formation by freeing atleast a portion of the oil from pores within the formation. Introductionof the aqueous displacement fluid into the formation may mobilize oilfor production therefrom by driving the oil through the formation in aplug-like flow.

The viscosity of the aqueous displacement fluid may be maintained uponintroduction to the formation and contact of the aqueous displacementfluid with the formation water and with the clays, minerals, and rock ofthe formation due to the relative equivalence of the MAR of divalentcations to monovalent cations of the aqueous displacement fluid and theformation water. Prior to introduction of the aqueous displacement fluidto the formation, the divalent cation and monovalent cation content ofthe formation water, the oil, and the clays, minerals, and rock of theformation is in relative equilibrium so the divalent cation andmonovalent cation concentration of the formation water, of the oil, andof the formation are relatively constant. Introduction of the aqueousdisplacement fluid into the formation to mobilize the oil therein doesnot disturb this equilibrium since the MAR of divalent cations tomonovalent cations of the aqueous displacement fluid and the formationwater are similar even though the TDS content of the aqueousdisplacement fluid may be significantly different than the formationwater TDS content. As a result, viscosity of the aqueous displacementfluid is not significantly changed upon contact with the formation waterand the formation rock by ion exchange with the formation water andformation rock, and the polymer of the aqueous displacement fluid is notprecipitated.

Referring now to FIG. 4, a system 200 for practicing a process of thepresent invention is shown. The system includes a first well 201 and asecond well 203 extending into an oil-bearing formation 205 such asdescribed above. The oil-bearing formation 205 may be comprised of oneor more formation portions 207, 209, and 211 formed of porous materialmatrices, such as described above, located beneath an overburden 213. Anaqueous displacement fluid as described above is provided. The aqueousdisplacement fluid may be provided from an aqueous displacement fluidstorage facility 215 fluidly operatively coupled to a firstinjection/production facility 217 via conduit 219. Firstinjection/production facility 217 may be fluidly operatively coupled tothe first well 201, which may be located extending from the firstinjection/production facility 217 into the oil-bearing formation 205.The aqueous displacement fluid may flow from the firstinjection/production facility 217 through the first well to beintroduced into the formation 205, for example in formation portion 209,where the first injection/production facility 217 and the first well, orthe first well itself, include(s) a mechanism for introducing theaqueous displacement fluid into the formation. Alternatively, theaqueous displacement fluid may flow from the aqueous displacement fluidstorage facility 215 directly to the first well 201 for injection intothe formation 205, where the first well comprises a mechanism forintroducing the aqueous displacement fluid into the formation. Themechanism for introducing the aqueous displacement fluid into theformation 205 via the first well 201—located in the firstinjection/production facility 217, the first well 201, or both—may becomprised of a pump 221 for delivering the aqueous displacement fluid toperforations or openings in the first well through which the aqueousdisplacement fluid may be introduced into the formation.

The aqueous displacement fluid may be introduced into the formation 205,for example by injecting the aqueous displacement fluid into theformation through the first well 201 by pumping the aqueous displacementfluid through the first well and into the formation. The pressure atwhich the aqueous displacement fluid is introduced into the formationmay range from the instantaneous pressure in the formation up to thefracture pressure of the formation or exceeding the fracture pressure ofthe formation. The pressure at which the aqueous displacement fluid maybe injected into the formation may range from 10% to 95%, or from 20% to90%, of the fracture pressure of the formation. The pressure at whichthe aqueous displacement fluid is injected into the formation may beselected to limit degradation of polymer in the aqueous displacementfluid by shear, where lower injection pressures limit degradation of thepolymer by shear. Preferably the aqueous displacement fluid is injectedinto the formation at pressures of from 10% to 50% of the fracturepressure of the formation.

The volume of the aqueous displacement fluid introduced into theformation 205 via the first well 201 may range from 0.001 to 5 porevolumes, or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore volumes,or from 0.2 to 0.9 pore volumes, where the term “pore volume” refers tothe volume of the formation that may be swept by the aqueousdisplacement fluid between the first well 201 and the second well 203.The pore volume may be readily be determined by methods known to aperson skilled in the art, for example by modeling studies or byinjecting water having a tracer contained therein through the formation205 from the first well 201 to the second well 203.

Introduction of the aqueous displacement fluid to the formation maymobilize oil in the formation for production from the formation. As theaqueous displacement fluid is introduced into the formation 205 throughthe first well 201, the aqueous displacement fluid spreads into theformation as shown by arrows 223. The aqueous displacement fluidcontacts the oil in the porous matrix material of the formation andpushes the oil through the formation to the second well 203 forproduction from the formation. Fingering of the aqueous displacementfluid through the oil or the oil through the aqueous displacement fluidmay be inhibited by the viscosity of the aqueous displacement fluidrelative to the viscosity of the oil, and in a preferred embodiment theaqueous displacement fluid mobilizes and drives the oil through theformation in a substantially plug-like flow.

The mobilized oil and the aqueous displacement fluid may be pushedacross the formation 205 from the first well 201 to the second well 203by further introduction of more aqueous displacement fluid or byintroducing water into the formation subsequent to introduction of theaqueous displacement fluid into the formation. The water may beintroduced into the formation 205 through the first well 201 aftercompletion of introduction of the aqueous displacement fluid into theformation to force or otherwise displace the oil and the aqueousdisplacement fluid toward the second well 203 for production.

The water to be introduced into the formation after introduction of theaqueous displacement fluid into the formation may be stored in, andprovided for introduction into the formation 205 from, a water storagefacility 225 that may be fluidly operatively coupled to the firstinjection/production facility 217 via conduit 227. The water to beintroduced into the formation after introduction of the aqueousdisplacement fluid into the formation preferably has an MAR of divalentcations to monovalent cations that is from 70% to 130% of the MAR ofdivalent cations to monovalent cations of the aqueous displacementfluid, and preferably the water is provided from a source utilized toprovide the water for the aqueous displacement fluid. The firstinjection/production facility 217 may be fluidly operatively coupled tothe first well 201 to provide the water to the first well forintroduction into the formation 205. Alternatively, the water storagefacility 225 may be fluidly operatively coupled to the first well 201directly to provide water to the first well for introduction into theformation 205. The first injection/production facility 217 and the firstwell 201, or the first well itself, may comprise a mechanism forintroducing the water into the formation 205 via the first well 201. Themechanism for introducing the water into the formation 205 via the firstwell 201 may be comprised of a pump or a compressor for delivering thewater to perforations or openings in the first well through which thewater may be injected into the formation. The mechanism for introducingthe water into the formation 205 via the first well 201 may be the pump221 utilized to inject the aqueous displacement fluid into the formationvia the first well 201.

The water may be introduced into the formation 205, for example, byinjecting the water into the formation through the first well 201 bypumping the water through the first well and into the formation. Thepressure at which the water may be injected into the formation 205through the first well 201 may be up to or exceeding the fracturepressure of the formation, or from 20% to 99%, or from 30% to 95%, orfrom 40% to 90% of the fracture pressure of the formation, or greaterthan the fracture pressure of the formation, and preferably issubstantially the same pressure utilized to inject the aqueousdisplacement fluid into the formation.

The amount of water introduced into the formation 205 via the first well201 following introduction of the aqueous displacement fluid into theformation through the first well may range from 0.001 to 5 pore volumes,or from 0.01 to 2 pore volumes, or from 0.1 to 1 pore volumes, or from0.2 to 0.6 pore volumes, where the term “pore volume” refers to thevolume of the formation that may be swept by the water between the firstwell and the second well. The amount of water introduced into theformation 205 should be sufficient to drive the mobilized oil and theaqueous displacement fluid across at least a portion of the formation.

Oil may be mobilized for production from the formation 205 via thesecond well 203 by introduction of the aqueous displacement fluid and,optionally, water into the formation through the first well 201, wherethe mobilized oil is driven through the formation from the first well201 for production from the second well 203 as indicated by arrows 229.At least a portion of the aqueous displacement fluid may pass throughthe formation 205 from the first well 201 to the second well 203 forproduction from the formation along with the mobilized oil.

After introduction of the aqueous displacement fluid and, optionally,water into the formation 205 via the first well 201, oil may berecovered and produced from the formation via the second well 203. Amechanism may be located at the second well for recovering and producingoil from the formation 205 subsequent to introduction of the aqueousdisplacement fluid into the formation. The mechanism for recovering andproducing oil from the formation may also recover and produce at least aportion of the aqueous displacement fluid, other water, and/or gas fromthe formation subsequent to introduction of the aqueous displacementfluid into the formation. The mechanism located at the second well 203for recovering and producing the oil, the aqueous displacement fluid,other water, and/or gas may be comprised of a pump 233, which may belocated in a second injection/production facility 231 and/or within thesecond well 203. The pump 233 may draw the oil, at least a portion ofthe aqueous displacement fluid, other water, and/or gas from theformation 205 through perforations in the second well 203 to deliver theoil, at least a portion of the aqueous displacement fluid, other water,and/or gas, to the second injection/production facility 231.

Alternatively, the mechanism for recovering and producing the oil, atleast a portion of the aqueous displacement fluid, other water, and/orgas from the formation 205 may be comprised of a compressor 234 that maybe located in the second injection/production facility 231. Thecompressor 234 may be fluidly operatively coupled to a gas storage tank241 via conduit 236, and may compress gas from the gas storage tank forinjection into the formation 205 through the second well 203. Thecompressor may compress the gas to a pressure sufficient to driveproduction of oil, the aqueous displacement fluid, other water, and/orgas from the formation via the second well 203, where the appropriatepressure may be determined by conventional methods known to thoseskilled in the art. The compressed gas may be injected into theformation from a different position on the second well 203 than the wellposition at which the oil, aqueous displacement fluid, other water,and/or gas are produced from the formation, for example, the compressedgas may be injected into the formation at formation portion 211 whileoil, aqueous displacement fluid, other water, and/or gas are producedfrom the formation at formation portion 209.

Oil, at least a portion of the aqueous displacement fluid, other water,and/or gas may be drawn from the formation 205 as shown by arrows 229and produced up the second well 203 to the second injection/productionfacility 231. The oil may be separated from gas and an aqueous mixturecomprised of the produced portion of aqueous displacement fluid andother formation water produced from the formation, for example connatewater, mobile water, or water from a oil recovery waterflood. Theproduced oil may be separated from the produced aqueous mixture andproduced gas in a separation unit 235 located in the secondinjection/production facility 231 and, in an embodiment, operativelyfluidly coupled to the mechanism 233 for recovering and producing oil,the components of the aqueous mixture, and/or gas from the formation.

A brine solution having a TDS content of greater than 20,000 ppm, orfrom 25,000 ppm to 250,000 ppm may be provided from a brine solutionstorage facility 247 to the separation unit 235 via conduit 273 formixing with the produced oil and the produced aqueous mixture, andoptionally with produced gas. The brine solution may have a TDS contentof at least 20,000 ppm, or at least 25,000 ppm, or at least 30,000 ppm,or at least 40,000 ppm, or at least 50,000 ppm, or from 20,000 ppm to250,000 ppm, or from 25,000 ppm to 200,000 ppm, or from 30,000 ppm to150,000 ppm, or from 40,000 ppm to 100,000 ppm. The brine solution maybe selected from seawater, brackish water, estuarine water, orproduction water produced from the formation and separated from oiland/or gas produced from the formation. Alternatively, the brinesolution may be comprised of at least a portion of a brine retentate117, a primary brine retentate 125 and/or a secondary brine retentate127, or a first brine retentate 137 and/or a second brine retentate 143(as shown in FIGS. 1-3) produced by contact of a saline source waterwith an ionic filter as described above.

A demulsifier may also be provided to the separation facility 235 from ademulsifier storage facility 271 which may be fluidly operativelyconnected to the separation unit via conduit 240. The demulsifier may beprovided to the separation facility 235 for mixing with the producedoil, the produced water, and the brine solution, and optionally withproduced gas, to facilitate separation of the produced oil and theproduced water.

The demulsifier may be selected from the group consisting of amylresins;butylresins; nonylresins; acid- or base-catalyzed phenol-formaldehyderesins; phenol-acrylate anhydride polyglycol resins; urethanes;polyamines; polyesteramines; sulfonates; di-epoxides; polyols; estersand polyol esters including triol fatty acid esters, triol adipateesters, and triol fumarate esters; ethoxylated and/or propoxylatedcompounds of amyl resins, butylresins, nonylresins, acid- orbase-catalyzed phenol-formaldehyde resins, fatty acids, polyamines,di-epoxides, and polyols; and combinations thereof which may bedispersed in a carrier solvent selected from the group consisting ofxylene, toluene, heavy aromatic naphtha, isopropanol, methanol,2-ethoxyhexanol, diesel, and combinations thereof. A suitabledemulsifier for separating the oil and water produced from the formation205 may be selected by conducting a bottle test, a conventional testknown to those skilled in the art for selecting a demulsifier effectiveto separate crude oil and water. Commercially available demulsifiersinclude the EB-Series from National Chemical Supply, 4151 SW 47^(th)Ave., Davie, Fla., 33314, United States, and Tretolite demulsifiers fromBaker Petrolite Corporation, 12645 W. Airport Blvd., Sugar Land, Tex.77478, United States.

In an embodiment of a method of the present invention the first well 201may be used for injecting the aqueous displacement fluid and,optionally, water into the formation 205 and the second well 203 may beused to produce and separate oil, water, and optionally gas from theformation as described above for a first time period, and the secondwell 203 may be used for injecting the aqueous displacement fluid and,optionally, water into the formation 205 to mobilize the oil in theformation and drive the mobilized oil across the formation to the firstwell and the first well 201 may be used to produce and separate oil,water, and gas from the formation for a second time period, where thesecond time period is subsequent to the first time period. The secondinjection/production facility 231 may comprise a mechanism such as pump251 that is fluidly operatively coupled the aqueous displacement fluidstorage facility 215 by conduit 253 and that is fluidly operativelycoupled to the second well 203 to introduce the aqueous displacementfluid into the formation 205 via the second well. The pump 251 may alsobe fluidly operatively coupled to the water storage facility 225 byconduit 255 to introduce water into the formation 205 via the secondwell 203 subsequent to introduction of the aqueous displacement fluidinto the formation via the second well. The first injection/productionfacility 217 may comprise a mechanism such as pump 257 or compressor 258for production of oil, water, and gas from the formation 205 via thefirst well 201. The first injection/production facility 217 may alsoinclude a separation unit 259 for separating produced oil, producedwater, and produced gas fluidly operatively connected to the mechanism257 by conduit 260, where the separation unit 259 may be similar toseparation unit 235 as described above. The brine solution storagefacility 247 may be fluidly operatively connected to the separation unit259 by conduit 272 to provide brine solution to the separation unit 259,and the demulsifier storage facility 271 may be fluidly operativelyconnected to the separation unit 259 by conduit 262 to providedemulsifier to the separation unit 259. The separation unit 259 may befluidly operatively coupled to the liquid storage tank 237 by conduit261 for storage of produced and separated oil in the liquid storage tankand to the gas storage tank 241 by conduit 265 for storage of producedgas in the gas storage tank.

The first well 201 may be used for introducing the aqueous displacementfluid and, optionally, subsequently water into the formation 205 and thesecond well 203 may be used for producing and separating oil, water, andgas from the formation for a first time period; then the second well 203may be used for introducing the aqueous displacement fluid and,optionally, subsequently water into the formation 205 and the first well201 may be used for producing and separating oil, water, and gas fromthe formation for a second time period; where the first and second timeperiods comprise a cycle. Multiple cycles may be conducted which includealternating the first well 201 and the second well 203 betweenintroducing the aqueous displacement fluid and, optionally, subsequentlywater into the formation 205, and producing and separating oil, water,and gas from the formation, where one well is introducing and the otheris producing and separating for the first time period, and then they areswitched for a second time period. A cycle may be from about 12 hours toabout 1 year, or from about 3 days to about 6 months, or from about 5days to about 3 months. The aqueous displacement fluid may be introducedinto the formation at the beginning of a cycle and water may beintroduced at the end of the cycle. In some embodiments, the beginningof a cycle may be the first 10% to about 80% of a cycle, or the first20% to about 60% of a cycle, the first 25% to about 40% of a cycle, andthe end may be the remainder of the cycle.

Referring now to FIG. 5 an array of wells 500 is illustrated. Array 500includes a first well group 502 (denoted by horizontal lines) and asecond well group 504 (denoted by diagonal lines). In some embodimentsof the method of the present invention, the first well of the methoddescribed above may include multiple first wells depicted as the firstwell group 502 in the array 500, and the second well of the methoddescribed above may include multiple second wells depicted as the secondwell group 504 in the array 500.

Each well in the first well group 502 may be a horizontal distance 530from an adjacent well in the first well group 502. The horizontaldistance 530 may be from about 5 to about 5,000 meters, or from about 7to about 1,000 meters, or from about 10 to about 500 meters, or fromabout 20 to about 250 meters, or from about 30 to about 200 meters, orfrom about 50 to about 150 meters, or from about 90 to about 120 meters,or about 100 meters. Each well in the first well group 502 may be avertical distance 532 from an adjacent well in the first well group 502.The vertical distance 532 may be from about 5 to about 5,000 meters, orfrom about 7 to about 1,000 meters, or from about 10 to about 500meters, or from about 20 to about 250 meters, or from about 30 to about200 meters, or from about 50 to about 150 meters, or from about 90 toabout 120 meters, or about 100 meters.

Each well in the second well group 504 may be a horizontal distance 536from an adjacent well in the second well group 504. The horizontaldistance 536 may be from about 5 to about 5,000 meters, or from about 7to about 1,000 meters, or from about 10 to about 500 meters, or fromabout 20 to about 250 meters, or from about 30 to about 200 meters, orfrom about 50 to about 150 meters, or from about 90 to about 120 meters,or about 100 meters. Each well in the second well group 504 may be avertical distance 538 from an adjacent well in the second well group504. The vertical distance 538 may be from about 5 to about 5,000meters, or from about 7 to about 1,000 meters, or from about 10 to about500 meters, or from about 20 to about 250 meters, or from about 30 toabout 200 meters, or from about 50 to about 150 meters, or from about 90to about 120 meters, or about 100 meters.

Each well in the first well group 502 may be a distance 534 from theadjacent wells in the second well group 504. Each well in the secondwell group 504 may be a distance 534 from the adjacent wells in firstwell group 502. The distance 534 may be from about 5 to about 5,000meters, or from about 7 to about 1000 meters, or from about 10 to about500 meters, or from about 20 to about 250 meters, or from about 30 toabout 200 meters, or from about 50 to about 150 meters, or from about 90to about 120 meters, or about 100 meters.

Each well in the first well group 502 may be surrounded by four wells inthe second well group 504. Each well in the second well group 504 may besurrounded by four wells in the first well group 502.

In some embodiments, the array of wells 500 may have from about 10 toabout 1,000 wells, for example from about 5 to about 500 wells in thefirst well group 502, and from about 5 to about 500 wells in the secondwell group 504.

In some embodiments, the array of wells 500 may be seen as a top viewwith first well group 502 and the second well group 504 being verticalwells spaced on a piece of land. In some embodiments, the array of wells500 may be seen as a cross-sectional side view of the formation with thefirst well group 502 and the second well group 504 being horizontalwells spaced within the formation.

To facilitate a better understanding of the present invention, thefollowing example of certain aspects of some embodiments is given. In noway should the following example be read to limit, or define, the scopeof the invention.

EXAMPLE

An experiment was conducted to determine the effect of using a lowsalinity aqueous displacement fluid containing a polymer and having aTDS content of less than 5,000 ppm and less than half the TDS content ofa formation water and having a MAR within 70% to 130% of the MAR of theformation water on viscosity and divalent cation exchange in anoil-bearing formation relative to an aqueous displacement fluid formedby combining a polymer with formation water. The amount of polymerrequired to provide the same viscosity was measured for the low salinityaqueous displacement fluid and the aqueous displacement fluid formed bycombining a polymer with formation water.

A sandstone core was aged with crude oil for 4 weeks at a temperature of50° C. (corresponding to the formation temperature of the formation fromwhich the crude oil was obtained). Diffraction analysis showed that thecore material was composed of 95% quartz with the remaining 5%containing illite-smectite, kaolinite, and illite-mica clays,K-feldspar, and traces of chlorite, anhydrite, calcite, and pyrite. Thecore was then saturated with synthetic formation water having thecomposition shown in Table 1.

A designed low salinity water solution was prepared having a TDS contentof 2170 ppm (2.5× dilution relative to the TDS of the formation water)and a MAR of divalent cations to monovalent cations equal to the MAR ofdivalent cations to monovalent cations of the synthetic formation water(MAR of the designed low salinity water solution=99% of the MAR of thesynthetic formation water). The composition of the low salinity watersolution is shown in Table 1.

A high salinity polymer solution (HSP) and a low salinity polymersolution (LSP) were formed from the synthetic formation water and thedesigned low salinity water solution, respectively. Sufficienthydrolyzed polyacrylamide polymer FLOPAAM 3630S was added to thesynthetic formation water and to the designed low salinity watersolution to produce an HSP solution and an LSP solution each having aviscosity of 125 cP at 50° C. The HSP solution contained 2483 ppm of thepolymer and the LSP solution contained 1761 ppm of the polymer.

TABLE 1 Synthetic formation water Designed LS water NaCl 4.517 g/L NaCl1.807 g/L KCl 0.000 g/L KCl 0.000 g/L CaCl₂•2H₂O 0.359 g/L CaCl₂•2H₂O0.058 g/L Na2SO4 0.497 g/L Na2SO4 0.199 g/L NaHCO3 0.293 g/L NaHCO30.117 g/L MgCl₂•6H₂O 0.059 g/L MgCl₂•6H₂O 0.009 g/L Na⁺ 2.018 g/L Na⁺0.807 g/L K⁺ 0.000 g/L K⁺ 0.000 g/L Ca²⁺ 0.098 g/L Ca²⁺ 0.016 g/L Mg²⁺0.007 g/L Mg²⁺ 0.001 g/L SO4 0.336 g/L SO4 0.134 HCO3 0.213 g/L HCO30.085 Cl⁻ 2.9339 g/L Cl⁻ 1.127 g/L MAR 38.8 MAR 38.3 meq/l ppm meq/l TDS5605.745 ppm TDS 2170.604 TDS

The core saturated with synthetic formation water was then treatedsequentially with 30 PV of the synthetic formation water, then 30 PV ofthe designed low salinity water, then 80 PV of the HSP solution, then 30PV of the designed LSP solution. The effluent from each of these stepswas collected in 3 ml fractions. The concentration of sodium, potassium,calcium, and magnesium cations of the effluent fractions from each stepwas measured by inductive coupled plasma elemental analysis to determinethe stripping effect of the injected water and polymer solutions. FIGS.10 and 11 show the measured concentrations of Na⁺, Ca²⁺, Mg²⁺, and K⁺ inthe effluents of the injected synthetic formation brine, the designedlow salinity water, the HSP solution, and the LSP solution. Theconcentration of Ca²⁺ and Mg²⁺ in the HSP solution effluent and the LSPsolution effluent is slightly higher than the concentration of thesecations in the HSP and LSP solutions at the beginning of the injectionof each of these solutions, which may be an effect of the affinity ofthe polymer for calcium and magnesium. Over the course of the injectionsof the HSP and LSP solutions, however, the calcium and magnesiumconcentrations in the effluent quickly revert to the baseline of theconcentrations of these cations in the injected solutions Importantly,the LSP solution does not show a significant stripping of Ca²⁺ and Mg²⁺relative to the HSP solution, indicating that the low salinity of theLSP solution does not induce any significant amount of stripping of thecalcium and magnesium cations from the core.

The viscosity of the effluent from the HSP solution injection and theLSP solution injection effluents was measured by a rheometer. FIG. 12shows the viscosity of the HSP solution effluent and the LSP solutioneffluent. Each effluent shows a viscosity drop of about 10% occurring atthe beginning of the injection, then the viscosity levels out.Significantly, the viscosity drop of the LSP solution is substantiallysimilar to the viscosity drop of the HSP solution, indicating that theviscosity of the LSP solution is not significantly affected by the lowsalinity of the LSP solution. This may correlate to the LSP solution notstripping substantial quantities of Ca²⁺ and Mg²⁺ from the core, whichmay be attributable to the MAR of the LSP solution being equivalent tothe MAR of the HSP solution.

The present invention is well adapted to attain the ends and advantagesmentioned above as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. While systems and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps.Whenever a numerical range with a lower limit and an upper limit isdisclosed, any number and any included range falling within the range isspecifically disclosed. In particular, every range of values (of theform, “from a to b,” or, equivalently, “from a-b”) disclosed herein isto be understood to set forth every number and range encompassed withinthe broader range of values. Whenever a numerical range having aspecific lower limit only, a specific upper limit only, or a specificupper limit and a specific lower limit is disclosed, the range also mayinclude any numerical value “about” the specified lower limit and/or thespecified upper limit. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an”, as used in theclaims, are defined herein to mean one or more than one of the elementthat it introduces.

What is claimed:
 1. A process for producing oil from an oil-bearing formation, comprising: determining the mass action ratio of divalent cations to monovalent cations of water from the oil-bearing formation; providing an aqueous displacement fluid comprising water and an ionically charged polymer, wherein the water of the aqueous displacement fluid has a total dissolved solids content of from 200 parts per million by weight (ppmw) to 5,000 ppmw and a mass action ratio of divalent cations to monovalent cations from 70% to 130% of the mass action ratio of divalent cations to monovalent cations of the water from the oil-bearing formation; introducing the aqueous displacement fluid into the oil-bearing formation to displace oil within the formation; producing oil from the oil-bearing formation subsequent to introducing the aqueous displacement fluid into the formation.
 2. The process of claim 1 further comprising the steps of: determining the viscosity of oil of the oil-bearing formation at a temperature within the range of temperatures in the formation; providing the aqueous displacement fluid having a viscosity of from 10% to 500% of the viscosity of the oil of the oil-bearing formation, where the viscosity of the aqueous displacement fluid is determined at the temperature at which the viscosity of the oil of the oil-bearing formation is determined.
 3. The process of claim 2 wherein the ionic polymer of the aqueous displacement fluid is mixed with the water of the aqueous displacement fluid in an amount effective to increase the viscosity of the water of the aqueous displacement fluid to a viscosity of from 10% to 500% of the viscosity of the oil of the oil-bearing formation.
 4. The process of claim 1 wherein the ionically-charged polymer is a water-dispersible polymer.
 5. The process of claim 1 wherein the ionically-charged polymer is a water soluble polymer.
 6. The process of claim 1 wherein the ionically-charged polymer is a selected from the group consisting of a water-soluble polyacrylamide, a water-soluble polyacrylate, a partially hydrolyzed water-soluble polyacrylamide, and mixtures thereof.
 7. The process of claim 1 wherein the MAR of divalent cations to monovalent cations of water of the oil-bearing formation is determined by obtaining a sample of water from the oil-bearing formation, measuring the concentrations of each divalent cation species and each monovalent cation species in the water obtained from the oil-bearing formation, and calculating the MAR of the water obtained from the oil-bearing formation according to formula (I) MAR_(fw)=(C ⁺ _((fw)))² /C ²⁺ _((fw)))  (I) where MAR_(fw) is the mass action ratio of divalent cations to monovalent cations of the water from the formation, C⁺ _((fw)) is the sum of the concentrations of the monovalent cation species in the water from the formation, and C²⁺ _((fw)) is the sum of the concentrations of the divalent cation species in the water from the formation.
 8. The process of claim 1 wherein the water of the aqueous displacement fluid is provided from a natural source water having a TDS content of from 200 ppm to 5,000 ppm.
 9. The process of claim 1 wherein the water of the aqueous displacement fluid is provided from a saline source water having a TDS content greater than 10,000 ppm wherein the saline source water is treated to adjust the TDS content of the saline source water to within a range of from 200 ppm to 5,000 ppm.
 10. The process of claim 1 wherein the water of the aqueous displacement fluid is provided from a source water having a TDS content less than 500 ppm wherein the source water is treated to adjust the TDS content of the source water to within a range of from 500 ppm to 5,000 ppm.
 11. The process of claim 1 wherein the water of the aqueous displacement fluid is provided from a source water having a MAR of divalent cations to monovalent cations that is from 70% to 130% of the MAR of divalent cations to monovalent cations of the water of the formation, where the MAR of the water of the aqueous displacement fluid is calculated according to formula (II) MAR_(adf)=(C ⁺ _((adf)))² /C ²⁺ _((adf)))  (II) where MAR_(adf) is the mass action ratio of divalent cations to monovalent cations of the water of the aqueous displacement fluid, C⁺ _((adf)) is the sum of concentrations of monovalent cation species in the water of the aqueous displacement fluid, and C²⁺ _((adf)) is the sum of concentrations of divalent cation species in the water of the aqueous displacement fluid.
 12. The process of claim 1 wherein the water of the aqueous displacement fluid is provided from a source water having a MAR of divalent cations to monovalent cations that is less than 70% or greater than 130% of the MAR of divalent cations to monovalent cations of the water of the formation and the MAR of divalent cations to monovalent cations of the source water is adjusted to a range of from 70% to 130% of the MAR of divalent cations to monovalent cations of the water of the formation, where the MAR of the water of the aqueous displacement fluid is calculated according to formula (II) MAR_(adf)=(C ⁺ _((adf)))² /C ²⁺ _((adf)))  (II) where MAR_(adf) is the mass action ratio of divalent cations to monovalent cations of the water of the aqueous displacement fluid, C⁺ _((adf)) is the sum of concentrations of monovalent cation species in the water of the aqueous displacement fluid, and C²⁺ _((adf)) is the sum of concentrations of divalent cation species in the water of the aqueous displacement fluid.
 13. The process of claim 1 further comprising producing water from the oil-bearing formation along with oil from the oil-bearing formation and separating the produced oil from the produced water. 